GB2615055A

GB2615055A - Wellbore apparatus for setting a downhole tool

Info

Publication number: GB2615055A
Application number: GB2306760.6A
Authority: GB
Inventors: Allen Schultz William Jr; W Teale David; C Davis Richard
Original assignee: Weatherford Technology Holdings LLC
Current assignee: Weatherford Technology Holdings LLC
Priority date: 2019-02-07
Filing date: 2020-01-24
Publication date: 2023-07-26
Anticipated expiration: 2040-01-24
Also published as: GB2615055B; GB202306760D0; US20200256142A1; GB2597125A; GB202207353D0; GB2604302A; US11643892B2; GB202001021D0; GB2597125B; GB2581268A; GB2581268B; GB202106938D0; NO20200142A1; US11248428B2; US20220145711A1; GB2604302B

Abstract

A first aspect relates to a method of separating a downhole tubular comprising running a tool (100, Fig 1) into a wellbore to a predetermined location on a work string. Flow actuated slips 220 are actuated and the slips are maintained in the set position by providing a first upward force on the work string. The work string is rotated to operate a cutter assembly disposed on the work string below the slips. This separates an upper portion of the tubular from a lower portion. The upper portion of tubing and the tool are pulled from the wellbore. A second aspect relates to a method of separating a downhole tubular that incorporates the features of the first aspect, in addition to applying a second higher upward force on the work string to unlock and set a packer 300; flowing fluid through the work string and into an annular area between tubular and a borehole; and reducing the second upward force on the work string to unset and re-lock the packer. The annular area is accessible through a cut formed between the upper and lower portions by the cutter assembly.

Description

WELLBORE APPARATUS FOR SETTING A DOWN HOLE TOOL

BACKGROUND Field

mon Embodiments described herein generally relate to a wellbore apparatus for setting a downhole tool. More particularly, the embodiments relate to an apparatus and methods for setting a packer downhole.

Description of the Related Art

[0002] Downhole operations are often accomplished with multiple tools on a single work string. Depending on the operation required, the tools are operated in a predetermined sequence. In some instances, it is necessary to ensure one tool does not operate prematurely. There is a need for a downhole mechanism to prevent inadvertent or premature operation of a tool. More specifically, there is a need to prevent inadvertent or premature setting of a downhole packer.

SUMMARY

[0003] The present disclosure generally relates to a locking system for a downhole tool comprising a first portion having a plurality of displaceable members, a second portion disposed around the first portion; a locked position wherein axial movement between the members is prevented; and an unlocked position wherein axial movement between the members is permitted. In one embodiment, the invention includes a downhole tool comprising a set of slips for maintaining the tool in an axial location in a wellbore. The slips are flow-actuated initially and then maintained in a set position due to a first upward force applied to the tool in the wellbore. A packer for sealing an annular area around the tool includes a locking system actuated by an additional upward force applied to the tool in the wellbore. In one embodiment, the tool is used in connection with a cutting tool to sever and remove a section of a tubular string lining the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

[0004] So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.

[0005] Figure 1 is a front view of a tool according to one embodiment of the invention.

[0006] Figure 2 is a section view of the tool of Figure 1.

[0007] Figure 3A is an exploded view showing different parts of the tool.

[0008] Figure 3B is an exploded view showing different parts of the tool.

[0009] Figure 3C is an exploded view showing different parts of the tool.

[0010] Figure 3D is an exploded view showing different parts of the tool.

[0011] Figures 4A-D are section views showing the tool in a run-in positon in a wellbore, the tool having a slip assembly and a packer assembly.

[0012] Figures 5A-D are section views showing the tool with slips of the slip assembly set in the wellbore and a locking system of the packer assembly in a locked position.

[0013] Figures 6A-D are section views showing the tool in the wellbore with the locking system of the packer in an unlocked position.

[0014] Figures 7A-D are section views of the tool showing the packer set in the wellbore.

DETAILED DESCRIPTION

[0015] Embodiments of the present disclosure including a tool having a slip assembly and a packer assembly having a locking system to prevent inadvertent or premature setting of the packer.

[0016] Figure 1 is a front view of a tool 100 according to one embodiment of the invention. The tool described herein is one that includes a slip assembly 200 and a packer assembly 300, with the packer having a locking system 400 that prevents operation of and setting of the packer until certain conditions are met. Embodiments also include a cutting tool (not shown) disposed below the tool on the same work string. It will be understood however that any number of different tools could be utilized with the tool described herein and the locking system described in relation to the packer assembly 300 is of use on any number of different tools where inadvertent actuation is a potential problem. Figure 2 is a section view of the tool 100 of Figure 1.

[0017] Figure 3A is an exploded view showing different parts of the tool 100. The portions illustrated generally refer to the slip assembly 200 visible in an assembled manner in Figures 4A, B. Included are a cap 203, an upper 205 and lower 210 piston surfaces as well as a spring 212 and spring housing 215 to bias the plurality of slips in a run-in and unset position. A slip housing 225 is shown as well as an exemplary slip 220 and slip retainer 230. The various parts of the slip assembly 200 are installed on a mandrel 110.

[0018] Figure 3B is an exploded view showing the parts of the slip assembly 200 as well as a portion of the locking system 400 for the packer assembly 300. Areas of Figure 3B labeled A and B correspond to similarly labeled areas of Figure 3C. Visible is a housing for sub-assemblies 252 with anti-rotation keys 256 and ribs 115 disposed there upon. The keys interact with key slots 258 formed in piston body adjacent piston surface 210 and ribs 115 interact with slots 130 (Figure 3D) to permit axial but not rotational movement. Fluid passageways 254 serve to provide a fluid path for fluid used to set the slip assembly 200. Also visible are portions of the slip assembly 200 with the slips 220 installed as well as the upper and lower piston bodies with piston surfaces 205, 210 formed thereon for flow-actuating the slips. Also shown are portions of the locking system 400 for the packer assembly 300 consisting of a collet sleeve 410 having displaceable collet fingers 415 and stop sleeve 336, the functions of which will be described herein.

[0019] Figure 3C is an exploded view showing different parts of the tool. On the left hand side of the tool are packer elements 320 separated by spacers 321 that correspond to area A of Figure 3B and will be disposed on the mandrel 110 below the slip assembly 200 of Figure 3B. A slot housing 325 includes slots 330 that correspond to the anti-rotation ribs 115 of Figure 3B. On the right side of the Figure are additional portions of the locking system 400 for the packer including a collet housing 420 for housing the collet sleeve 410 of Figure 3B as well as a spring loaded sleeve 425 and a spring 430 and spring housing 431 for urging the sleeve upwards into contact with the collet sleeve 410.

[0020] Figure 3D is an exploded view showing different parts of the tool. In the center of the Figure is the mandrel 110 constructed and arranged to be rotatable in order to rotate another tool (not shown) disposed on the lower end of mandrel via threads 112. The mandrel includes radially disposed fluid slots 235 for the passage of fluid in order to set the slip assembly 200. On each side of the Figure are components, most of which are prevented from rotation by a keyed arrangement between a ring with lugs 120 that operates in conjunction with a sleeve 125 having mating vertical slots 130 permitting axial but not rotational movement between the components. A bearing member 135 facilitates the rotation of the mandrel 110 and other center portions of the assembly in relation to the outer portions.

[0021] Figures 4A-D are section views showing the tool 100 in a run-in positon in a wellbore, the tool including the slip assembly 200 and packer assembly 300 with its locking system 400. In this document the term "wellbore wall" refers to an inside wall of a tubular that lines the earthen borehole. Portions of the slip assembly already introduced are visible in Figure 4A including the cap 203, upper and lower piston surfaces 205, 210 and a port 235 providing a fluid path between an interior of the mandrel 110 and the two piston surfaces. The fluid path includes ports 235 formed in the mandrel 110 as well as fluid passageways 254 formed in the sub-assembly housing 252. Figure 4B illustrates additional portions of the slip assembly 200 including the slips 220 and a conical shape 240 that serves to urge the slips outwards and into contact with the wellbore wall as they are set. Generally, the slip assembly includes a number of slips 220 constructed and arranged to be urged along the conically shaped member 240 and into a wedging relationship with the walls of the surrounding wellbore 101.

[0022] In the embodiment shown, the slips 220 are biased in an unset position by spring 212, the force of which must be overcome to move the cap/ slip combination downwards in relation to the conical shape 240. The slips are further held in the run-in position by set screws 245 temporarily connecting the slip members to the conical shape 240. The slip assembly 200 is flow-actuated by pumping fluid through the work string (not shown) upon which the tool 100 is mounted and run into the well. Port 235 (there are typically several radially spaced around the mandrel) located in a wall of the mandrel 110 permits fluid communication between the work string and the two piston surfaces 205, 210, one associated with the slip members and one associated with that part of the assembly on which the conical shape 240 is formed. Fluid pressure separates the two pistons and in doing so, overcomes the bias of the spring 212, causing the set screws 245 to fail and moves the slips 220 to a set position as shown in Figures 5A-D. The slips are thereafter retained in the set position due to an upward force applied to the mandrel 110 from the surface which creates a wedge-like condition between the conical shape 240, slips 220, and the wellbore wall 101.

[0023] Shown primarily in Figures 4B-D is the packer assembly 300 with its locking system 400. The packer is unset. Shown in Figure 4B are the packing elements 320 and spacers 321 of Figure 3C, each of which is compressible. The elements are retained at an upper end by a downwardly facing shoulder of the conical shape 240 and at a lower end by an upward facing shoulder movable relative to the underside in order to compress the packer elements. As the slips are set in the wellbore, the packer assembly 300 remains in its original, unset position.

[0024] Figures 5A-D are section views showing the tool with slips of the slip assembly set in the wellbore and the locking system 400 of the packer retaining the packer in its unset position. Fluid pressure delivered through port 235 has moved lower piston 210 to a lower positon relative to the pod and with it, the cap 203 which has compressed the biasing spring 212 that was biasing the slip assembly 200 in the run-in positon. As can be appreciated from Figure 5B, the set screws 245 have failed and the slips 220 have moved down and out along the conical shape 240 and into contact with the walls of the wellbore 101. Although the slips 220 have been set, the packer assembly 300 remains in the unset position.

[0025] The locking system 400 of the packer 300 prevents its inadvertent actuation.

The locking system includes the collet sleeve 410 with its radially disposed fingers 415, all of which must be deflected inwardly in order to unlock the packer and allow it to be set. In Figure 4C two of the fingers are visible. An enlarged view of the locking system in the area of the fingers 415 is provided on the left side of the Figure. Each finger has an outwardly facing tab 435 that, in the locked positon rests above an inwardly facing upset 440 that extends around an adjacent inner surface 442 of the collet housing 420. The upset 440 can also be appreciated in Figure 3C. To unlock the packer, it is necessary to move the collet housing upwards in relation to the collet sleeve 410. The position of the upset 440 under the tabs 435 prevents that from happening until enough upwards force is applied to the collet housing to allow an angled surface 416 of the upset 440 to interact with a corresponding angled surface 418 of the fingers and deflect the fingers inwards far enough for the upset to move past the fingers (Figure 6C). Just below the tabs 435 of the fingers 415 is a spring-loaded sleeve 425 biased upwards by a spring 430 against an underside of the upset. The purpose of the sleeve is to keep the collet fingers in their deflected position as the collet housing 420 moves upwards as the packer elements 320 are compressed from below. In one embodiment, the sleeve 425 is dimensioned whereby the tabs 435 are forced inwards an additional distance as can be appreciated by comparing Figures 5C, 6C, and 7C. The purpose of an additional, slight deflection is to facilitate resetting of the locking system whereby two "steps" are created as the tabs move outwards to their original, non-deflected position as shown in 5C.

[0026] Figures 6A-D are section views showing the tool in the wellbore with the slip assembly 200 set and the locking system 400 of the packer in an unlocked position. As shown clearly in Figure 6C, the components of the packer assembly 300 and locking system are shown at the instant when the packer is unlocked due to relative movement between the inwardly facing upset 440 of the collet housing 420 and the outwardly facing tabs 435 of the collet fingers 415. As illustrated, the collet fingers have been deflected inwards due to upward force applied to the collet housing 420 which has permitted a sliding action between angles 416, 418 of the upset 440 and tabs 435 of the fingers 415. The tabs of the displaced fingers have come to rest on an upper end of the spring-loaded sleeve 425 in order to keep them deflected and permit the locking system 400 to be re-set if needed.

[0027] The force required to deflect the fingers and "unlock" the locking mechanism of the packer assembly 300 is supplied from the surface where, in one embodiment, 70,000 lbs. of upward force is required over and above the upward force already keeping the slip assembly 200 set against the wellbore wall. The upward force on the work string acts primarily on an enlarged diameter portion 140 of the mandrel 110 visible in Figure 6D. The enlarged diameter portion serves to urge the movable parts of the lower portion of the assembly, including the collet housing 420 upwards as if they are being pushed, in order to set the packer once the locking system has been unlocked. The distance needed to compress the elements 320 and set the packer is a distance equal to the gap 335 shown between L-shaped member 250 and stop sleeve 336 in Figure 6D.

[0028] Figures 7A-D are section views of the tool showing the packer assembly 200 set in the wellbore 101. As with Figures 5A-D and 6A-D, the slip assembly 200 remains set due to upward fore on the mandrel 110 via a work string from the surface of the well. Comparing the Figures to 6A-D, the upward force applied to unlock the packer assembly has moved the mandrel and its enlarged diameter portion upwards along with the collet housing 420. The result is a movement between the parts equal to the gap 335 shown in Figure 6D. The portions of the locking system are in essentially the same position as they were in Figures 6A-D. However, that part of the assembly associated with the collet housing 420 has moved upwards in relation to the collet sleeve 410 in order to compress the packer elements 320. In Figure 7D, the gap 335 of Figure 6D has now been closed, reflecting the distance that the elements 320 have been compressed. As described herein, the locking system 400 of the packer assembly 300 requires a high upward force on the work string to move the upset 440 of the collet housing 420 against the tabs 435 of the fingers 415 in order to displace the fingers inward and permit upward movement of the housing. Once unlocked, the movement required to actually set the packer and compress the element requires little force and, due the upward force remaining on the string, takes place instantaneously. As shown in Figures 7A-D, the packer element has been compressed between the underside 241 of the conical shape 240 and the upward facing shoulder formed at the lower end of the element.

[0029] In operation, the assembly of the present invention can be utilized in a number of different ways. In one example, the tool is used with a cutting tool for separating an upper portion of a casing in the wellbore from a lower portion. Cutting tools for severing tubulars in a wellbore are well known. One example is described in US patent publication number 2018/0258734 assigned to the same assignee as the present invention and that publication is incorporated herein in its entirety. Preferably, the cutting tool has radially extendable cutters that extend outwardly at a predetermined time into contact with the walls of the surrounding tubular. Thereafter, the tubing is severed by rotational movement of the cutting tool. As described herein, a center portion of the tool 100, including the mandrel 110 is constructed and arranged to be rotatable relying in pad on bearing member 135 and various keyed relationships between portions of the tool, like the ring with lugs 120 and slots 130 of sleeve 125.

[0030] In one embodiment, the tool 100 is run into a wellbore 101 on a work string with a cutting tool (not shown) disposed on the string therebelow. The purpose of the operation is to sever a tubular lining the wellbore. The combination of tools is run into a location adjacent the location where the surrounding tubular is to be severed. Thereafter, fluid is pumped through the work string and through port 235 formed in a wall of the mandrel 110. As the fluid acts upon two opposing piston surfaces 205, 210, set screws 245 pinning the slips 220 in a run-in position relative to the conical shape 240 are broken and the slips are moved downwards along the conical member and into contact with the walls of the surrounding tubular. Thereafter, an upward force is applied to the work string to keep the slips set in a wedging relationship between the conical shape and the wellbore wall 101. With the tool combination fixed in a predetermined location in the wellbore, the cutting tool is operated by rotating the work string from the surface while upward force is maintained to keep the slips set. Once the cutting tool has successfully severed the tubular, the entire assembly including the upper portion of the tubular is lifted using the slips that remain engaged. Due to the weight of the severed tubular being lifted, the packer in most cases will be unlocked and moved to a set positon. However, in this operation having the packer set has no bearing on the result of retrieving the tubular portion to the surface of the well.

100311 In another scenario, the operation is carried out as above but, due to interference by wellbore debris between the tubular lining the wellbore and the borehole therearound, the severed tubular cannot be successfully lifted. In this instance, additional lifting force is applied to the work string from the surface of the well. At about 75,000 lbs. of force, the locking system 400 of the packer assembly 300 is unlocked according to the operations described in relation to the forgoing Figures, especially Figures 5C and 6C. Thereafter, fluid is pumped out a lower end of the string, below the cutting tool where it "washes" the area between an outer surface of the tubular and the borehole therearound using the area where the tubular was cut as a fluid path to the outer surface. In this manner, debris such as dirt that can hamper the lifting and separation of the upper portion of the tubular from the lower portion can be disturbed. In some instances, another packer is set below the cutting tool so that the washing fluid is trapped between the lower packer and the packer of the tool 100, forcing it out of the tubular and into the area of the borehole. In other instances, a cement plug previously placed in the wellbore creates a barrier below the tool. In addition to its "washing" function, the fluid pumped between the packers/ cement plug can be pressurized and provide additional lifting force. If the operation is successful, the tool, cutting tool and upper section of tubular are lifted to the surface with the slip and packer assembly remaining set.

[0032] In yet another scenario, the initial lifting is unsuccessful and the washing procedure described above is also unsuccessful in loosening the upper portion of tubular to a point where it can be dislodged and raised. In this case, the entire assembly including the tool 100 and cutting tool can be repositioned at another, typically higher location where the process will be attempted again. In order to reposition the assembly, the slips and packer must first be unset. By reducing lifting force on the string, the locking system 400 of the packer assembly 300 is first re-set as the collet housing 420 with its inwardly facing upset 440 is moved down relative to the collet sleeve 410 with its displaced fingers 415 with their outwardly extending tabs 435. Due to the same angles 416, 418 of the upset 440 and tabs 435, the re-setting of the locking system requires relatively little force compared to the 70,000 lbs. necessary to move them to the unlocked position. Once the packer is returned to its unset position with its locking system re-set, additional downward movement releases the slips and the spring-loaded cap urges the slips to their run-in position. Thereafter, the assembly including the tool 100 and cutting tool, or any other tool attached thereto, can be raised to a higher location in the wellbore where the slip assembly 200 will be reset and if needed, the locking system 400 of the packer 300 can be unlocked and the packer set just as it was in the prior attempt.

[0033] While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

The disclosure may be further exemplified by the following numbered clauses.

1. A downhole tool comprising: a set of slips for maintaining the tool in an axial location in a wellbore, the slips flow actuated and then maintained in a set position due to a first force applied to the tool in the wellbore; and a packer for sealing an annular area around the tool, the packer including a locking system, the locking system unlocked by an additional force applied to the tool in the wellbore while the slips remain set.

2. The tool of clause 1, wherein the locking system includes a collet sleeve with inwardly displaceable fingers and a collet housing surrounding the sleeve, the sleeve and housing having opposing angles constructed and arranged to prevent the sleeve and housing from axial movement relative to one another until the fingers are displaced due to a force placed on the sleeve.

3. The tool of clause 2, wherein one of the opposing angles is formed on a formation in the interior of the housing and the other of the opposing angles is formed on an outwardly extending tab formed on each finger.

4. The tool of any preceding clause, wherein the additional force to unlock the packer is about 70,000 lbs.

5. The tool of any preceding clause, further including a cutting tool disposed below the tool on the same work string, the cutting tool for severing a tubular lining a wellbore.

6. The tool of clause 5, wherein the cutting tool is operated by rotation of the work string.

7. The tool of clause 5 or 6, wherein the tool is constructed and arranged whereby when the cutting tool is rotated, the slips and packer are prevented from rotation.

8. The tool of any preceding clause, wherein the locking system is re-actuated by a release of the additional force.

9. The tool of any preceding clause, wherein the slips are unset by release of the first force.

10. The tool of any preceding clause, wherein the first force and the additional force are applied from the surface of the wellbore.

11. The tool of any preceding clause, wherein the first force and the additional force are upward forces.

12. A method of separating a downhole tubular comprising: running a tool into a wellbore to a predetermined location on a work string; actuating flow actuated slips; maintaining slips in a set position by providing a first upward force on the work string rotating the work string to separate an upper portion of the tubular from a lower portion using a cutter assembly disposed on the work string below the slips; and pulling the upper portion of the tubing and the tool from the wellbore.

13 A method of separating a downhole tubular comprising: running a tool into a wellbore to a predetermined location on a work string; actuating flow actuated slips; maintaining slips in a set position by providing a first upward force on the work string; rotating the work string to separate an upper portion of the tubular from a lower portion using a cutter assembly disposed on the work string below the slips; applying a second higher upward force on the work string to unlock and set a packer; flowing fluid through the work string and into an annular area between tubular and a borehole therearound, the annular area accessible through a cut formed between the upper and lower portions by the cutter assembly; reducing the second upward force on the work string to unset and re-lock the packer; and pulling the upper portion of the tubing from the wellbore.

14. A downhole apparatus comprising: a set of slips for maintaining the tool in an axial location in a wellbore, the slips flow actuated and maintained in a set position due to a first upward force applied to the tool in the wellbore; and a tool for performing a downhole task, the apparatus including a locking system to prevent premature actuation of the tool, the locking system unlocked by an additional upward force applied to the tool in the wellbore while the slips remain set.

15. A locking system for a downhole tool comprising: a first portion including a collet sleeve having a plurality of displaceable members, a second portion disposed around the first portion, the second portion including a collet housing; a locked position wherein axial movement between the members is prevented; and an unlocked position wherein axial movement between the members is permitted and wherein the displaceable members of the collet sleeve are displaced in the unlocked position, the displaceable members each including a tab formed on an outer surface thereof, each tab including a lower tab angle and the collet housing including an upset formed on an inner surface thereof, the upset including an upper angled surface constructed and arranged to matingly contact the lower tab angles of the displaceable members in the locked position.

16. The locking system of clause 15, wherein moving the system from the locked to the unlocked position requires enough upward movement of the second portion relative to the first position for the upper angled surface of the upset to move past the lower tab angles, thereby deflecting the displaceable members inwards a first distance and permitting axial movement between the sleeve and the housing.

17. The locking system of clause 15 or 16, wherein after the system is unlocked, the displaceable members are deflected a second additional distance.

18. The locking system of any one of clauses 15 to 17, wherein movement from the locked to the unlocked position requires a first higher force and movement from the unlocked to the locked position requires a second lesser force.

Claims

Claims: 1. A method of separating a downhole tubular comprising: running a tool into a wellbore to a predetermined location on a work string; actuating flow actuated slips; maintaining the slips in a set position by providing a first upward force on the work string; rotating the work string to separate an upper portion of the tubular from a lower portion using a cutter assembly disposed on the work string below the slips; and pulling the upper portion of the tubing and the tool from the wellbore.
2. The method of claim 1, prior to pulling the upper portion, further comprising: applying a second higher upward force on the work string to unlock and set a packer; and flowing fluid through the work string and into an annular area between tubular and a borehole therearound, the annular area accessible through a cut formed between the upper and lower portions by the cutter assembly.
3 The method of claims 1 or 2, further comprising: unsetting the packer and the slips; repositioning the packer and the slips to a second position in the wellbore; and setting the packer and the slips at the second position.
4. The method of any preceding claim, wherein unsetting the packer comprises reducing the second upward force on the work string.
5. The method of any preceding claim, wherein the packer is set at the second position by applying a second higher upward force on the work string.
6. The method of any preceding claim, wherein the flow actuated slips are actuated by pumping a fluid through the work string, wherein a port located in the wall of the mandrel permits the fluid to travel between the work string and the flow actuated slips.
7. The method of claim 2, prior to flowing fluid through the work string, further comprising setting a second packer below the cutting tool.
8. The method of any preceding claim, wherein unsetting the packer includes locking a locking system on the work string.
9. The method of any preceding claim, wherein setting the packer includes unlocking the locking system on the work string.
10. The method of any preceding claim, wherein unsetting the packer and the slips comprises unsetting the packer prior to unsetting the slips.
11. The method of any preceding claim, wherein unsetting the packer requires less force than setting the packer.
12. A method of separating a downhole tubular comprising: running a tool into a wellbore to a predetermined location on a work string; actuating flow actuated slips; maintaining slips in a set position by providing a first upward force on the work string rotating the work string to separate an upper portion of the tubular from a lower portion using a cutter assembly disposed on the work string below the slips; applying a second higher upward force on the work string to unlock and set a packer; flowing fluid through the work string and into an annular area between tubular and a borehole therearound, the annular area accessible through a cut formed between the upper and lower portions by the cutter assembly; reducing the second upward force on the work string to unset and re-lock the packer; and pulling the upper portion of the tubing from the wellbore.